1. Field
This invention relates generally to fluids and procedures for hydraulically fracturing subterranean formations to stimulate production of crude oil and natural gas from wells. More specifically, this invention relates to chemical agents called "breakers" which are added to fracturing fluids to reduce the viscosity of fracturing fluids when the fracturing procedure is completed.
2. Background Art
Crude oil and natural gas residing in subterranean porous formations are produced by drilling wells into the formations. Oil and/or natural gas flow into the well driven by the pressure gradient which exists between the formation and the well, gravity drainage, fluid displacement, and capillary action. Typically, surface pumps are required to supplement the natural driving forces to bring the hydrocarbons to the wellhead surface.
Most wells are hydraulically fractured to increase flow. The drill pipe casing section adjacent to the zone to be fractured is perforated using explosive charges or water jets. Then a fracturing fluid is pumped down the drill pipe at a rate and pressure high enough to fracture the formation. The fractures propagate from the well bore radially outward forming either or both vertical and horizontal cracks. Most fractures form vertical cracks in formations.
Solid particles called proppants are dispersed into the fracturing fluid. Proppants lodge in the cracks and hold them open after fracturing fluid hydraulic pressure is released and the fracturing fluid flows back into the well. Without proppants, the cracks would close and the increased permeability gained by the fracturing operation would be lost. To preclude the cracks from closing prematurely, proppants must have sufficient compressive strength to resist crushing, but also-must be sufficiently abrasion resistant and non-angular to preclude imbedding into the formation. The type and size of propping agents are usually selected to complement the characteristics of the formation being fractured.
In formations under moderate pressure, 6000 psi or less, the most commonly used propping agent is ordinary screened river sand. Special grades of silica sand are used. For formations with closure stresses above about 6000 psi, resin-coated sand proppants are preferred. These are high quality silica sands which have been coated with a thermoset phenolic resin. The resin coating imparts an optimum crush resistance and compressibility to the sand particles to optimize propping action. There are two types of resin coatings: those that cure in-situ; and those that are precured. Curable coatings generally are used where proppant flow-back can occur.
Fracturing fluids are water-based compositions containing a hydratable high molecular weight polymeric gelling material which increases the viscosity of the fluid. The fluid must be thickened to reduce leakage from the fracture fissures during fracturing and to suspend the proppant. A wide variety of hydratable viscosifiers are used in fracturing fluid formulations including polysaccharides, polyacrylamides and polyacrylamide copolymers. Polysaccharides are currently favored. Particularly desirable polysaccharides include galactomannan gums, derivatives thereof, and cellulose derivatives. Specific polysaccharides include guar gum, locust bean gum, carboxymethylguar, hydroxyethylguar, hydroxypropylguar, carboxymethylhydroxypropylguar, carboxymethylhydroxyethylguar, sodium hydroxymethyl cellulose, sodium-hydroxymethyl cellulose, sodium carboxymethylhydroxyethyl cellulose, and hydroxyethyl cellulose. Generally, the molecular weights of the hydratable polymers used in fracturing fluids range from about 500,000 to about 3,000,000. The ratio of apparent viscosity of the fracturing fluid relative to water at shear rates encountered in well fractures is between about 500 to 1000.
The amount of viscosifier employed depends on the desired working viscosity of the fluid and the downhole temperature of the formation to be fractured. Typically, from about 10 to 100 lbs of viscosifier per 1000 gallons of fracturing fluid is employed.
Viscosity generally decreases with temperature, so the viscosifier concentration would have to be increased to achieve a required viscosity in the formation. However, the amount of thickener required can make the fracturing fluid difficult to formulate and pump. Crosslinking the polysaccharide provides a better solution. Polysaccharides contain hydroxyl groups in the cis form on adjacent carbon atoms which can be crosslinked to increase fracturing fluid viscosity. Crosslinking is particularly useful for fracturing higher temperature formations, those over 200.degree. F.
Common crosslinking agents include polyvalent ions in their high valance state such as Ti(IV) and Zr(IV). Also, borate ions are effective crosslinkers for polysaccharides.
When the fracturing operation is complete, the fracturing fluid must be expelled from the fissures so that production of oil or gas can begin. The viscosity of the fracturing fluid preferably is reduced ("broken") so that it can flow back out of the fissures and into the well. Hydratable polymers may decompose spontaneously in time from either bacteriological or thermal degradation. But, at formation temperatures below about 225.degree. F., the natural degradation is too slow and too much production time is lost. Accordingly, for wells below about 225.degree. F., a chemical agent referred to as a "breaker" is added to the fracturing fluid to accelerate viscosity reduction. Breakers operate by breaking the backbone chain of the hydrated polymer. Breakers may be added to the fracturing fluid at the surface "on-the-fly" as the fluid is being pumped down the well. Ideally, the breaker should be dormant until the fracturing operation has been completed, and then the breaker should rapidly reduce the fluid viscosity. Enzyme breakers such as alpha and beta amylases, amyloglucosidase, oligoglucosidase invertase, maltase, cellulase, and hemicellulose are commonly used for wells having a bottomhole temperature below about 150.degree. F. and with fracturing fluids with pH between about 3.5 and 8. Enzymes catalyze the hydrolysis of glycosidic bonds between the monomer units of polysaccharides.
Peroxygen compounds are the preferred breakers for higher temperature formations. They form free radicals which break the backbone of gel polymer chains. Peroxides generally decompose over a narrow temperature range characteristic of the peroxide. Accordingly, premature viscosity breaking generally may be precluded by selecting a peroxygen with a decomposition temperature close to the temperature in the fractured formation so that peroxide does not decompose until it is heated to formation temperature. Commonly used peroxygen breakers include dichromates, permanganates, peroxydisulfates, sodium perborate, sodium carbonate peroxide, hydrogen peroxide, tertiarybutylhydroperoxide, potassium diperphosphate, and ammonium and alkali metal salts of dipersulfuric acid. Typical breaker addition rates range from about 2 to 10 lbs. per thousand gallons of fracturing fluid.
The most common oxidative breakers are peroxydisulfates (S.sub.2 O.sub.8 .dbd.) which decompose into highly reactive sulfate radical anions. Decomposition is slow below 120.degree. F., but can be accelerated by adding amines. Peroxydisulfates decompose rapidly above 125.degree. F. The amount of peroxydisulfate required decreases with increasing formation temperature. As little as 0.25 lb per 1000 gal is required at 200.degree. F.
For higher temperature formations, peroxygens with correspondingly higher decomposition temperatures could be used.
Other chemicals added to fracturing fluids include bactericides to repress bacteria growth, oxygen, or free radical scavengers, such as methanol or sodium thiosulfate, to inhibit premature breaking, and a surfactant to repress foaming.
It has been observed that curable resin-coated proppants may interfere with the viscosity breaking action of peroxy breakers in fracturing fluids incorporating polysaccharide viscosifiers. For example, a ten-fold increase in the addition rate of persulfate breaker is required when using a curable resin-coated sand proppant relative to the amount required when using uncoated sand or bauxite proppant.
It is also known that enzyme and peroxygen breakers do not effectively reduce the viscosity of fracturing fluids incorporating polysaccharide viscosifiers in formations which are at low to moderate temperatures, that is, temperatures from about 50.degree. F. to about 120.degree. F. The low temperature viscosity breaking problem is discussed in U.S. Pat. No. 4,560,486, which teaches using a partially water soluble tertiary amine in conjunction with ammonium persulfates or alkali metal persulfates to break the viscosity breaker of fracturing fluids containing polysaccharide viscosifiers in formations in the 50.degree. F. to 120.degree. F. temperature range. In U.S. Pat. No. 4,552,672, Brown et al. report that the minimum practical temperature for peroxygen breakers can be decreased from 50.degree. C. to about 20.degree. C. by adding a soluble metal salt to accelerate peroxide decomposition, but that peroxide decomposition in the presence of metals is difficult to control and reproduce, and that adding metals makes the breaking unacceptable, erratic, and unreproduceable.
For the foregoing reasons there is a need for fracturing fluid breakers which can effectively break the viscosity of fracturing fluids comprising a polysaccharide viscosifier in conjunction with curable resin-coated proppants. There is also need for fracturing fluid breakers which effectively break the viscosity of fracturing fluids comprising polysaccharide viscosifiers in formations at temperature formations in problematic 50.degree. F. to 120.degree. F. range.